Method of enhancing treatment fluid placement in shale, clay, and/or coal bed formations

ABSTRACT

Provided are methods that include a method comprising: placing a treatment fluid into a well bore that penetrates a subterranean formation, wherein the subterranean formation comprises at least one selected from the group consisting of: a shale, a clay, a coal bed, and a combination thereof; and applying a pressure pulse to the treatment fluid.

BACKGROUND

The present invention relates to methods of treating a subterranean formation, and, at least in some embodiments, to methods of using one or more pressure pulses to enhance the effectiveness of placing a treatment fluid into a portion of a subterranean formation which comprises shales, clays, and/or coal beds.

A well bore drilled in a subterranean formation may penetrate portions of the formation that comprise shales, clays, and/or coal beds, which may be susceptible to degradation. For example, when contacted by aqueous fluids found in the subterranean formation or introduced therein as a treatment fluid, swelling of shales and/or clays can result in undesirable interference with subterranean operations. Additionally, degradation may substantially decrease the stability of the well bore, which may cause irregularities in the diameter of the well bore, e.g., the diameter of some portions of the well bore may be either smaller or greater than desired. In an extreme case, degradation may decrease the stability of the well bore to such an extent that the well bore collapses.

Subterranean formations comprising shales, clays, and/or coal beds generally have a low permeability. As used herein, the term “shale” refers to a sedimentary rock formed from the consolidation of fine clay and silt materials into laminated, thin bedding planes. As used herein, the term “clay” refers to a rock that may be comprised of, inter alia, one or more types of clay, including, but not limited to kaolinite, montmorillonite/smectite, illite, chlorite, and any mixture thereof. The clay content of the formations may be a single species of a clay mineral or several species, including the mixed-layer types of clay. As used herein, “coal bed” refers to a rock formation that may be comprised of, inter alia, one or more types of coal, including, but not limited to, peat, lignite, sub-bituminous coal, bituminous coal, anthracite, and graphite.

Many shales and/or clays are reactive with fresh water, resulting in ion exchange and absorption of aqueous fluids. The presence of aqueous fluids found in the subterranean formation or introduced therein as a treatment fluid may lead to significant swelling of the shales and/or clays and corresponding reductions in the mechanical strength of the subterranean formation. Moreover, the fine aggregate that composes shales and/or clays can pose problems if exposed to high stresses. For example, under high stress, shale can mechanically fail, resulting in the generation of fine clay materials that can be highly mobile in produced fluids. This can result in well bore sloughing and large quantities of solids production, plugging screens or filling separators on the surface. In some formations, the bonding between bedding plane layers may be weaker than the bonding between particles in a given layer. In such formations, the bedding plane may represent a weakness susceptible to mechanical failure or separation. To combat these problems, brines are often used that contain high ion concentration so that ion exchange will not occur and the reactivity of the shales and/or clays will be reduced. In extreme cases, oil-based fluids may be used to avoid exposing the shales and/or clays to aqueous fluids.

Several different types of treatments have been employed in subterranean operations to prevent the flow of aqueous fluids present in a well bore into the subterranean formation, and conversely, to prevent the flow of aqueous fluids residing in the subterranean formation into the well bore. For example, relative permeability modifiers and other substances (e.g., silicates, emulsion polymers) may be placed into the subterranean formation that may reduce the water-wettability of sands and rock in the formation matrix and/or the diffusion of water into the formation matrix. However, in order for these treatments to be effective, it may be necessary to place these substances with substantial penetration and relative uniformity throughout the formation, which may require high hydraulic pressures and/or complicated isolation techniques and equipment.

Pressure pulsing techniques have been used to enhance water injection for secondary oil recovery and to enhance fluid placement in matrix injection applications. The pressure pulsing techniques practiced heretofore have typically been conducted under matrix flow conditions. The pressure pulsing process may act through localized energy, overcoming capillary forces and formation dilatency to improve placement of fluids under matrix flow conditions. In low permeability formations, the ability to place large volumes of treatment fluids may be limited by the low effective porosity and permeability of these formations.

Finally, layered formations, such as formations comprising shales, clays, and/or coal beds may contain naturally occurring microfractures. Traditionally, these unconventional formations have been associated with non-productive rock by the petroleum industry. Recently, however, there have been a number of significant natural gas discoveries where the gas is located in a naturally fractured formation. In these applications, most of the effective porosity may be limited to the fracture network within the formation, but some gas may have also been trapped in the formation matrix or in the bedding planes.

SUMMARY

The present invention relates to methods of treating a subterranean formation, and, at least in some embodiments, to methods of using one or more pressure pulses to enhance the effectiveness of placing a treatment fluid into a portion of a subterranean formation which comprises shales, clays, and/or coal beds.

In one embodiment, a method of treating a subterranean formation comprises the following steps. Placing a treatment fluid into a well bore that penetrates a subterranean formation, wherein the subterranean formation comprises at least one selected from the group consisting of: a shale, a clay, a coal bed, and a combination thereof. Applying a pressure pulse to the treatment fluid.

In another embodiment, a method of treating a subterranean formation comprises the following steps. Placing a treatment fluid into a well bore that penetrates a subterranean formation, wherein the subterranean formation comprises at least one selected from the group consisting of: a shale, a clay, a coal bed, and a combination thereof. Applying a pressure pulse that exceeds the formation fracture gradient to the treatment fluid.

In another embodiment, a method of treating a subterranean formation comprises the following steps. Placing a treatment fluid into a well bore that penetrates a subterranean formation, wherein the subterranean formation comprises at least one selected from the group consisting of: a shale, a clay, a coal bed, and a combination thereof. Pressurizing the treatment fluid to a first pressure wherein the first pressure exceeds the ambient fluid pressure in the well bore. Applying a pressure pulse to the treatment fluid. In this embodiment, the minimum pressure of the pressure pulse exceeds the first pressure, and the maximum pressure of the pressure pulse exceeds the formation fracture gradient.

The features and advantages of the present invention will be readily apparent to those skilled in the art. While numerous changes may be made by those skilled in the art, such changes are within the spirit of the invention.

DESCRIPTION OF PREFERRED EMBODIMENTS

The present invention relates to methods of treating a subterranean formation, and, at least in some embodiments, to methods of using one or more pressure pulses to enhance the effectiveness of placing a treatment fluid into a portion of a subterranean formation which comprises shales, clays, and/or coal beds.

As used herein, the term “shale” refers to a sedimentary rock formed from the consolidation of fine clay and silt materials into laminated, thin bedding planes.

As used herein, the term “clay” refers to a rock that may be comprised of, inter alia, one or more types of clay, including, but not limited to kaolinite, montmorillonite/smectite, illite, chlorite, and any mixture thereof. The clay content of the formations may be a single species of a clay mineral or several species, including the mixed-layer types of clay.

As used herein, “coal bed” refers to a rock formation that may be comprised of, inter alia, one or more types of coal, including, but not limited to, peat, lignite, sub-bituminous coal, bituminous coal, anthracite, and graphite.

“Pressure pulse” or “pressure pulsing,” as referred to herein, will be understood to mean the effect or action of deliberately varying the fluid pressure in a subterranean formation through the application of periodic increases, or “pulses,” in the pressure of a fluid being placed into the formation. A “pressure pulse” should be understood to be a time-dependent raising and lowering of a fluid pressure, as would be clear to a person of ordinary skill in the art.

As used herein, a pressure pulse which “straddles or exceeds the formation fracture gradient” would be a pressure pulse wherein the maximum fluid pressure of the pulse is greater than the fracture gradient, and the minimum fluid pressure of the pulse may be either less than (in the case of “straddles”) or greater than (in the case of “exceeds”) the fracture gradient of the formation.

As used herein, the term “matrix flow conditions” is defined as a placement of a fluid conducted below the fracture gradient pressure of a subterranean formation, and/or below the parting pressure of a layered formation.

The term “formation fracture gradient” is defined to include a fluid pressure sufficient to create or enhance one or more fractures in the subterranean formation. As used herein, the “fracture gradient” of a layered formation also encompasses a parting fluid pressure sufficient to separate two or more adjacent bedding planes in a layered formation. It should be understood that a person of ordinary skill in the art could perform a simple leak-off test on a core sample of a formation to determine the fracture gradient of a particular formation.

“Enhance one or more fractures in a subterranean formation,” as that phrase is used herein, is defined to include the extension or enlargement of one or more natural or previously created fractures in the subterranean formation.

As used herein, the term “treatment fluid” refers to any fluid that may be used in a subterranean application in conjunction with a desired function and/or for a desired purpose. The term “treatment fluid” does not imply any particular action by the fluid or any component thereof.

As used herein, the term “dilation” refers to an expansion of a fracture and/or separation of a pair of adjacent bedding planes due to the force exerted by a fluid pressure pulse against the fracture walls and/or bedding plane surfaces.

No particular mechanism of consolidation or stabilization is implied by the term “consolidating agent.” The consolidating agents used in the present invention may provide adhesive bonding between formation particulates to alter the distribution of the particulates within the formation in an effort to reduce their potential negative impact on permeability and/or fracture conductivity. In some embodiments, the consolidating agents may cause formation particulates to become involved in collective stabilized masses and/or stabilize the formation particulates in place to prevent their migration that might negatively impact permeability and/or fracture conductivity.

If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.

The present invention provides, inter alia, methods for placing treatment fluids into a subterranean formation which comprises shales, clays, and/or coal beds using one or more pressure pulses which straddle or exceed the formation fracture gradient. One of the advantages of the present invention, many of which are not discussed or alluded to herein, is that a treatment fluid may be placed with more substantial penetration and relative uniformity throughout a subterranean formation. Moreover, the methods of the present invention may be used to increase the coverage of a treatment fluid into zones with different permeabilities, without requiring the use of an additive diverter. Additionally, the methods of the present invention may allow for the placement of an increased amount of a treatment fluid into low permeability formations versus the amount that is able to be placed into such formations under matrix flow conditions. In some applications, the introduction of a treatment fluid into a subterranean formation comprising shales, clays, and/or coal beds may cause the formation to shrink in volume and/or increase in mechanical strength. This may also act to stabilize the formation against production of fine particles. In some embodiments, this may be a result of introducing a treatment fluid into the subterranean formation that removes aqueous fluids from the formation. In some embodiments, the introduction of a treatment fluid may stabilize a formation comprising shales and/or clays, minimizing or ideally stopping swelling, crumbling, or dispersion of the clay or shale particles in the formation.

In certain embodiments, the methods of the present invention may comprise placing a treatment fluid into a well bore that penetrates a subterranean formation which comprises shales, clays, and/or coal beds, and applying a pressure pulse that straddles or exceeds the formation fracture gradient to the treatment fluid. Such a pressure pulse may affect the dilatency of existing and/or created fractures and act, inter alia, to provide additional energy to help overcome the effects of surface tension and capillary pressure within the fractures. By overcoming such effects, a treatment fluid may be able to penetrate the formation more substantially and with greater uniformity. In some embodiments where the pressure pulse straddles the formation fracture gradient, the pressure pulse may effectively introduce a treatment fluid into an existing fracture without substantially enhancing the existing fracture. In certain embodiments, pressure pulses that straddle the formation fracture gradient may be used in combination with pressure pulses that exceed the formation fracture gradient.

Without limiting the invention to a particular theory or mechanism of action, it is nevertheless currently believed that a pressure pulse or a series of pressure pulses as described herein may cause the dilation of one or more fractures, networks of fractures, and/or pairs of adjacent bedding planes in a subterranean formation. This dilation may be elastic in nature such that, as the energy dissipates from the formation, a pressure wave may efficiently propagate along a length of the fracture and/or bedding plane.

As previously mentioned, in certain embodiments, a pressure pulse that straddles or exceeds the formation fracture gradient is applied to a treatment fluid. The treatment fluid may be pressurized above the ambient fluid pressure in the well bore prior to the application of the pressure pulse. If the amplitude of the pressure pulse exceeds the formation fracture gradient, the treatment fluid may dilate any existing fracture, network of fractures, and/or pair of adjacent bedding planes and propagate there through. In addition, if the amplitude of the pressure pulse exceeds the formation fracture gradient, the treatment fluid may also create or enhance one or more fractures in the formation. As the pressure of the treatment fluid drops below the formation fracture gradient, the fracture or pairs of adjacent bedding planes may constrict, and the fluid placed therein may leak off into the formation along the expanded fracture walls or bedding plane surfaces. The surface area available for placing the treatment fluid into the formation may thereby be significantly increased.

In some embodiments, a second pressure pulse may be applied to the treatment fluid, wherein the pressure pulse again straddles or exceeds the formation fracture gradient so as to enhance the one or more fractures in the subterranean formation. As the fluid pressure again drops below the formation fracture gradient, the fracture or pairs of adjacent bedding planes may again constrict, thereby allowing the fluid placed therein to leak off into the formation along the expanded fracture walls or bedding plane surfaces. The process may be repeated, which may allow the one or more fractures, networks of fractures, and/or pairs of adjacent bedding planes to provide a larger surface area for placing the treatment fluid into the formation. This larger surface area may allow for much better placement of the treatment fluid in low permeability reservoirs than could be achieved through matrix injection. Pressure pulsing may limit fracture growth as compared to constant application of fluid pressure above the fracture gradient. Dilation and constriction of the fractures or pairs of adjacent bedding planes may result in more substantial penetration of the treatment fluid into the formation. Furthermore, local pressurization resulting from fluid placement may generate uniform stresses in the leak off area, thereby allowing a relatively uniform fracture network to be created.

The methods of the present invention may have utility for treating layered formations, such as for example, shales, clays, and/or coal beds. Layered formations may contain microfractures, which may be naturally occurring. Thus, in these embodiments, one or more pressure pulses may dilate one or more pairs of adjacent bedding planes and/or microfractures present in the layered formation. The dilation of the pairs of adjacent bedding planes and/or microfractures may result in a path for fluid flow that creates a large area for contact of a treatment fluid with the formation. Accordingly, in certain embodiments, the methods of the present invention may comprise placing a treatment fluid into a well bore penetrating a subterranean formation which comprises shales and/or coal beds, wherein the subterranean formation comprises one or more pairs of adjacent bedding planes, applying a pressure pulse to the treatment fluid straddles or exceeds the formation fracture gradient so as to at least partially separate one or more pairs of adjacent bedding planes. In some embodiments, dilation of the microfractures or pairs of adjacent bedding planes may significantly increase the surface area available for placement of a treatment fluid.

The pressure pulses of the methods of the present invention may be supplied by any device capable of applying a pressure pulse to a treatment fluid that straddles or exceeds the fracture gradient of a formation. In certain embodiments, the pressure of the treatment fluid in the well bore P₀ may be increased in a steady, rather than staccato, manner such that P₀ approaches the formation fracture gradient P_(f). This resulting state of such a pressurization may be described according to Equation I.

P ₀ >P _(f) −P ₀   (I)

When the conditions of Equation I are met, the amplitude of the pressure pulse P_(p) necessary to straddle or exceed the formation fracture gradient P_(f) may be relatively small compared to P₀. Alternatively, P₀ may be small compared to the formation fracture gradient P_(f), as described by Equation II.

P ₀ <P _(f) −P ₀   (II)

When the condition of Equation II are met, the amplitude of the pressure pulse P_(p) necessary to straddle or exceed the formation fracture gradient P_(f) may be relatively large compared to P₀.

The pulsing parameters may be selected to achieve desired results. For example, the pressure of the treatment fluid in the well bore, the amplitude of the pulse, and the frequency of the pulses may be adjusted. As would be understood by a person of ordinary skill in the art, factors to consider when selecting these parameters may include, inter alia, the viscosity of the treatment fluid, the fracture gradient of the subterranean formation, and the porosity of the subterranean formation. In some embodiments, the amplitude of the pulse may be in the range of from about 10 psi to about 3,000 psi. In some embodiments, the frequency of the pulse may be in the range of from about 0.001 Hz to about 1 Hz. Pressure pulsing methods are further discussed in U.S. Pat. No 7,114,560, issued to Nguyen, which is hereby incorporated by reference.

Placement of a treatment fluid with pressure pulsing may be advantageous for a variety of applications. For example, placement of a consolidation fluid into a subterranean formation comprising shales, clays, and/or coal beds may provide consolidation in the formation. Similarly, placement of a treatment fluid in a subterranean formation comprising shales, clays, and/or coal beds with pressure pulsing may result in shrinking of the formation and/or dehydration of the subterranean formation, which may increase the permeability and/or porosity of the subterranean formation. Remedial treatments, such as well bore cleanout, may also benefit by placing a treatment fluid with pressure pulsing.

Suitable pressure pulsing devices may include any device capable of applying a pressure pulse to a treatment fluid such that the pressure pulse straddles or exceeds the formation fracture gradient. Suitable pressure pulsing devices may include those attached to a wellhead and those placed within a well bore. Pressure pulsing devices attached to a wellhead may be connected to multiple well bores and may be operated to selectably supply pressure pulses to one or more of the well bores. One example of a pressure pulsing device that may be suitable for use in the methods of the present invention is the surface pressure pulsing system disclosed in U.S. Pat. No. 7,025,134 issued to Byrd et al., which is incorporated by reference herein. In some embodiments, the pressure pulsing device may be a high amplitude device. Lower amplitude devices may also be suitable according to other embodiments. One of ordinary skill in the art would be able to select an appropriate pressure pulsing device based on several factors, including the characteristics of the subterranean formation and/or the treatment fluid to be used. Another example of a pressure pulsing device that may be suitable for use in the methods of the present invention is a fluidic oscillator, examples of which are disclosed in U.S. Pat. Nos. 5,135,051, 5,165,438, and 5,893,383, which are incorporated by reference herein. Examples of commercially available pressure pulsing devices or systems may include Deepwave^(SM), available from Halliburton Energy Services, Duncan, Okla. (see also U.S. Patent Application No. 2006/0272821), and PowerWave™ Technology, commercially available from Wavefront Energy and Environmental Services USA Inc. of Cypress, Tex.

Generally, when treating subterranean formations comprising shales, clays, and/or coal beds, suitable treatment fluids may include, but are not limited to, treatment fluids that shrink or dehydrate the formation, treatment fluids that stabilize the formation, and treatment fluids that coat the formation surfaces. Such treatment fluids may, inter alia, affect the mechanical strength of at least a portion of the formation, reduce the volume of at least a portion of the formation, increase the flow capacity of the natural fractures and/or bedding planes within the formation, and/or make the formation less reactive to aqueous based fluids. Examples of suitable treatment fluids may include a treatment fluid comprising a cationic polymer, a cationic oligomer, a cation, a methanol, a glycerin, an ethylene glycol, a low molecular weight consolidation fluid, a polymeric composition, a quaternary ammonium compound having inorganic anions and carboxylate anions, a polymeric composition, a rheology stabilizer, a rheology thinner, a consolidation fluid, a stimulation fluid, a relative permeability modifier, or any combination thereof.

Suitable treatment fluids may include cationic polymers and oligomers, for example, poly(dimethyldiallylammonium chloride), cationic co-polymers of poly(acrylamide), and cationic poly(diemethylaminoethylmethacrylate). Commercially available suitable treatment fluids include BARACAT®, BARASIL-S™, BARO-TROL PLUS®, BORE-HIB™, BXR™, BXR™-L, CLAY FIRM®, CLAY SYNC™, CLAY SYNC II™, Cla-Sta® FS, Cla-Sta® XP, Clayfix™, Clayfix II™, Clayfix 3™, GEM™ CP, GEM™ GP, and HYDRO-GUARD® Fluid, each available from Halliburton's Baroid Fluid Services of Houston, Tex.

Another example of a treatment fluid suitable for use in the present invention is a treatment fluid comprising cations (including, but not limited to, potassium ions, calcium ions, ammonium ions, hydrogen ions, tetramethylammonium ion), salts that provide cations (including, but not limited to, potassium chloride, calcium chloride, sodium chloride, ammonium chloride, tetramethylammonium chloride, and other cationic oligomers), or mixtures thereof, any of which may be delivered by aqueous solutions or ionic liquids. Without limiting the invention to a particular theory or mechanism of action, it is nevertheless currently believed that when a treatment fluid comprising a high concentration of cations contacts a subterranean formation comprising shales and/or clays, the ions of the cationic salts may exchange with sodium ions commonly found in shale layers. This ion exchange may have the effect of reducing the volume of the shales and/or clays, wherein the shrinkage may increase the flow capability and/or affect the mechanical properties of the formation. In some embodiments, it may be desirable to select cations with a small ionic radius, a high charge density, and/or a small hydration sphere. For example, in some embodiments, the cations may have hydration spheres with diameters in the range of about 10 to about 25 Angstroms.

Other suitable treatment fluids which dehydrate shales, clays, and/or coal beds may include, for example, methanol, glycerin, and ethylene glycol.

Suitable treatment fluids may also include low molecular weight consolidation fluids. As used herein, the term “low molecular weight consolidation fluid” refers to a consolidation fluid with a molecular weight of less than about 1000. It is believed that low molecular weight consolidation fluids would exhibit low viscosities during pumping operations, such as viscosities less than about 100 centipoise, when measured at room temperature when using a Fann model 50. Such fluids may include, for example, monomeric or oligomeric compositions which may be polymerized, acrylics, maleic acid derivatives, and furfuryl alcohol. (See “An Improved Sand Consolidation Process with Clay Conditioning,” SPE 1339 (1965), B. M. Young, Society of Petroleum Engineers.)

Suitable treatment fluids also include certain quaternary ammonium compounds having inorganic anions and carboxylate anions, as discussed in U.S. Pat. No. 5,097,904, which is herein incorporated by reference. Those quaternary ammonium compounds having carboxylate anions being entirely organic in nature are biodegradable and thus enjoy a greater environmental acceptance than those which do not have carboxylate anions.

Another example of a suitable treatment fluid may include a polymeric composition that may be used to, inter alia, stabilize reactive shales and/or clays in subterranean formations. As discussed in U.S. Pat. No. 7,091,159 issued to Eoff et al., which is hereby incorporated by reference, such polymeric compositions may stabilize the shales and/or clays, minimizing or ideally stopping degradation.

Suitable treatment fluids may also include rheology stabilizers or thinners for high-temperature high-pressure high mineralized degree drilling fluids as discussed in U.S. Pat. No. 6,436,878, issued to Wang et al., which is hereby incorporated by reference. Any of the previously discussed suitable treatment fluids may be delivered downhole in a pumpable multiple phase composition, as discussed in U.S. Pat. No. 6,464,009, issued to Bland et al., which is hereby incorporated by reference.

Other treatment fluids that may be useful according to the methods of the present invention may include, but are not limited to, consolidation fluids, stimulation fluids, and treatment fluids comprising substances such as relative permeability modifiers.

In some embodiments, suitable treatment fluids may include stimulation fluids. Stimulation fluids that may be suitable for use in the present invention may be acid or solvent-based. For example, hydrochloric acid may be a suitable stimulation fluid.

Consolidation fluids that may be suitable for use in the present invention may comprise at least one consolidation fluid selected from the group consisting of a resin, a tackifying agent, a gelable composition, and a combination thereof. Suitable tackifying agents may comprise any compound that, when in liquid form or in a solvent solution, will form a non-hardening coating upon a particulate. Suitable resins include all resins known in the art that are capable of forming a hardened, consolidated mass. Suitable gelable compositions may include those compositions that cure to form a semi-solid, immovable, gel-like substance. Examples of suitable gelable compositions include, but are not limited to, gelable resin compositions, gelable aqueous silicate compositions, crosslinkable aqueous polymer compositions, polymerizable organic monomer compositions, and combinations thereof. Consolidation fluids that may be suitable for use in the present invention may be further discussed in U.S. Pat. No. 7,114,560, issued to Nguyen, which is hereby incorporated by reference.

The concentration of treatment fluids may vary depending on the characteristics of the formation being treated. For example, shale formations may exhibit greater surface area and lower permeability than sandstone formations. Considerations when determining the concentration of a treatment fluid may include such factors as the surface area of the formation, or the viscosity required to provide appropriate pulsing parameters, as previously discussed. It should be understood that a person of ordinary skill in the art would be capable of analyzing these factors to determine appropriate the appropriate concentrations.

Consolidation fluids suitable for use in the present invention generally comprise at least one consolidating agent selected from the group consisting of a resin, a tackifying agent, a gelable composition, and a combination thereof. In some embodiments of the present invention, the viscosity of the consolidation fluid is less than about 100 cP, preferably less than about 50 cP, and still more preferably less than about 10 cP.

Resins suitable for use in the consolidation fluids of the present invention include all resins known in the art that are capable of forming a hardened, consolidated mass. Many such resins are commonly used in subterranean consolidation operations, and some suitable resins include two component epoxy based resins, novolak resins, polyepoxide resins, phenol-aldehyde resins, urea-aldehyde resins, urethane resins, phenolic resins, furan resins, furan/furfuryl alcohol resins, phenolic/latex resins, phenol formaldehyde resins, polyester resins and hybrids and copolymers thereof, polyurethane resins and hybrids and copolymers thereof, acrylate resins, and mixtures thereof. Some suitable resins, such as epoxy resins, may be cured with an internal catalyst or activator so that when pumped down hole, they may be cured using only time and temperature. Other suitable resins, such as furan resins generally require a time-delayed catalyst or an external catalyst to help activate the polymerization of the resins if the cure temperature is low (i.e., less than 250° F.), but will cure under the effect of time and temperature if the formation temperature is above about 250° F., preferably above about 300° F. It is within the ability of one skilled in the art, with the benefit of this disclosure, to select a suitable resin for use in embodiments of the present invention and to determine whether a catalyst is required to trigger curing.

Any solvent that is compatible with the resin and achieves the desired viscosity effect is suitable for use in the present invention. Preferred solvents include those listed above in connection with tackifying compounds. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine whether and how much solvent is needed to achieve a suitable viscosity.

Tackifying agents suitable for use in the consolidation fluids of the present invention comprise any compound that, when in liquid form or in a solvent solution, will form a non-hardening coating upon a particulate. A particularly preferred group of tackifying agents comprise polyamides that are liquids or in solution at the temperature of the subterranean formation such that they are, by themselves, non-hardening when introduced into the subterranean formation. A particularly preferred product is a condensation reaction product comprised of commercially available polyacids and a polyamine. Such commercial products include compounds such as mixtures of C₃₆ dibasic acids containing some trimer and higher oligomers and also small amounts of monomer acids that are reacted with polyamines. Other polyacids include trimer acids, synthetic acids produced from fatty acids, maleic anhydride, acrylic acid, and the like. Such acid compounds are commercially available from companies such as Witco Corporation, Union Camp, Chemtall, and Emery Industries. The reaction products are available from, for example, Champion Technologies, Inc. and Witco Corporation. Additional compounds which may be used as tackifying compounds include liquids and solutions of, for example, polyesters, polycarbonates, and polycarbamates, natural resins such as shellac and the like. Other suitable tackifying agents are described in U.S. Pat. No. 5,853,048 issued to Weaver, et al. and U.S. Pat. No. 5,833,000 issued to Weaver, et al., which are herein incorporated by reference.

Tackifying agents suitable for use in the present invention may be either used such that they form non-hardening coating or they may be combined with a multifunctional material capable of reacting with the tackifying compound to form a hardened coating. A “hardened coating” as used herein means that the reaction of the tackifying compound with the multifunctional material will result in a substantially non-flowable reaction product that exhibits a higher compressive strength in a consolidated agglomerate than the tackifying compound alone with the particulates. In this instance, the tackifying agent may function similarly to a hardenable resin. Multifunctional materials suitable for use in the present invention include, but are not limited to, aldehydes such as formaldehyde, dialdehydes such as glutaraldehyde, hemiacetals or aldehyde releasing compounds, diacid halides, dihalides such as dichlorides and dibromides, polyacid anhydrides such as citric acid, epoxides, furfuraldehyde, glutaraldehyde or aldehyde condensates and the like, and combinations thereof. In some embodiments of the present invention, the multifunctional material may be mixed with the tackifying compound in an amount of from about 0.01 to about 50 percent by weight of the tackifying compound to effect formation of the reaction product. In some preferable embodiments, the compound is present in an amount of from about 0.5 to about 1 percent by weight of the tackifying compound. Suitable multifunctional materials are described in U.S. Pat. No. 5,839,510 issued to Weaver, et al., which is herein incorporated by reference.

Solvents suitable for use with the tackifying agents of the present invention include any solvent that is compatible with the tackifying agent and achieves the desired viscosity effect. The solvents that can be used in the present invention preferably include those having high flash points (most preferably above about 125° F.). Examples of solvents suitable for use in the present invention include, but are not limited to, butylglycidyl ether, dipropylene glycol methyl ether, butyl bottom alcohol, dipropylene glycol dimethyl ether, diethyleneglycol methyl ether, ethyleneglycol butyl ether, methanol, butyl alcohol, isopropyl alcohol, diethyleneglycol butyl ether, propylene carbonate, d-limonene, 2-butoxy ethanol, butyl acetate, furfuryl acetate, butyl lactate, dimethyl sulfoxide, dimethyl formamide, fatty acid methyl esters, and combinations thereof. It is within the ability of one skilled in the art, with the benefit of this disclosure, to determine whether a solvent is needed to achieve a viscosity suitable to the subterranean conditions and, if so, how much.

Gelable compositions suitable for use in the present invention include those compositions that cure to form a semi-solid, immovable, gel-like substance. The gelable composition may be any gelable liquid composition capable of converting into a gelled substance capable of substantially plugging the permeability of the formation while allowing the formation to remain flexible. As referred to herein, the term “flexible” refers to a state wherein the treated formation is relatively malleable and elastic and able to withstand substantial pressure cycling without substantial breakdown of the formation. Thus, the resultant gelled substance stabilizes the treated portion of the formation while allowing the formation to absorb the stresses created during pressure cycling. As a result, the gelled substance may aid in preventing breakdown of the formation both by stabilizing and by adding flexibility to the treated region. Examples of suitable gelable liquid compositions include, but are not limited to, (1) gelable resin compositions, (2) gelable aqueous silicate compositions, (3) crosslinkable aqueous polymer compositions, and (4) polymerizable organic monomer compositions.

Certain embodiments of the gelable liquid compositions of the present invention comprise gelable resin compositions that cure to form flexible gels. Unlike the resin compositions described above, which generally cure into hardened masses, the gelable resin compositions cure into flexible, gelled substances that form resilient gelled substances. Gelable resin compositions allow the treated portion of the formation to remain flexible and to resist breakdown.

Generally, the gelable resin compositions useful in accordance with this invention comprise a curable resin, a diluent, and a resin curing agent. When certain resin curing agents, such as polyamides, are used in the curable resin compositions, the compositions form the semi-solid, immovable, gelled substances described above. Where the resin curing agent used may cause the organic resin compositions to form hard, brittle material rather than a desired gelled substance, the curable resin compositions may further comprise one or more “flexibilizer additives” (described in more detail below) to provide flexibility to the cured compositions.

Examples of gelable resins that can be used in the present invention include, but are not limited to, organic resins such as polyepoxide resins (e.g., Bisphenol a-epichlorihydrin resins), polyester resins, urea-aldehyde resins, furan resins, urethane resins, and mixtures thereof. Of these, polyepoxide resins are preferred.

Any solvent that is compatible with the gelable resin and achieves the desired viscosity effect is suitable for use in the present invention. Examples of solvents that may be used in the gelable resin compositions of the present invention include, but are not limited to, phenols; formaldehydes; furfuryl alcohols; furfurals; alcohols; ethers such as butyl glycidyl ether and cresyl glycidyl etherphenyl glycidyl ether; and mixtures thereof. In some embodiments of the present invention, the solvent comprises butyl lactate. Among other things, the solvent acts to provide flexibility to the cured composition. The solvent may be included in the gelable resin composition in an amount sufficient to provide the desired viscosity effect.

Generally, any resin curing agent that may be used to cure an organic resin is suitable for use in the present invention. When the resin curing agent chosen is an amide or a polyamide, generally no flexibilizer additive will be required because, inter alia, such curing agents cause the gelable resin composition to convert into a semi-solid, immovable, gelled substance. Other suitable resin curing agents (such as an amine, a polyamine, methylene dianiline, and other curing agents known in the art) will tend to cure into a hard, brittle material and will thus benefit from the addition of a flexibilizer additive. Generally, the resin curing agent used is included in the gelable resin composition, whether a flexibilizer additive is included or not, in an amount in the range of from about 5% to about 75% by weight of the curable resin. In some embodiments of the present invention, the resin curing agent used is included in the gelable resin composition in an amount in the range of from about 20% to about 75% by weight of the curable resin.

As noted above, flexibilizer additives may be used, inter alia, to provide flexibility to the gelled substances formed from the curable resin compositions. Flexibilizer additives may be used where the resin curing agent chosen would cause the gelable resin composition to cure into a hard and brittle material—rather than a desired gelled substance. For example, flexibilizer additives may be used where the resin curing agent chosen is not an amide or polyamide. Examples of suitable flexibilizer additives include, but are not limited to, an organic ester, an oxygenated organic solvent, an aromatic solvent, and combinations thereof. Of these, ethers, such as dibutyl phthalate, are preferred. Where used, the flexibilizer additive may be included in the gelable resin composition in an amount in the range of from about 5% to about 80% by weight of the gelable resin. In some embodiments of the present invention, the flexibilizer additive may be included in the curable resin composition in an amount in the range of from about 20% to about 45% by weight of the curable resin.

In other embodiments, the consolidation fluids of the present invention may comprise a gelable aqueous silicate composition. Generally, the gelable aqueous silicate compositions that are useful in accordance with the present invention generally comprise an aqueous alkali metal silicate solution and a temperature activated catalyst for gelling the aqueous alkali metal silicate solution.

The aqueous alkali metal silicate solution component of the gelable aqueous silicate compositions generally comprise an aqueous liquid and an alkali metal silicate. The aqueous liquid component of the aqueous alkali metal silicate solution generally may be fresh water, salt water (e.g., water containing one or more salts dissolved therein), brine (e.g., saturated salt water), seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation. Examples of suitable alkali metal silicates include, but are not limited to, one or more of sodium silicate, potassium silicate, lithium silicate, rubidium silicate, or cesium silicate. Of these, sodium silicate is preferred. While sodium silicate exists in many forms, the sodium silicate used in the aqueous alkali metal silicate solution preferably has a Na₂O-to-SiO₂ weight ratio in the range of from about 1:2 to about 1:4. Most preferably, the sodium silicate used has a Na₂O-to-SiO₂ weight ratio in the range of about 1:3.2. Generally, the alkali metal silicate is present in the aqueous alkali metal silicate solution component in an amount in the range of from about 0.1% to about 10% by weight of the aqueous alkali metal silicate solution component.

The temperature-activated catalyst component of the gelable aqueous silicate compositions is used, inter alia, to convert the gelable aqueous silicate compositions into the desired semi-solid, immovable, gelled substance described above. Selection of a temperature-activated catalyst is related, at least in part, to the temperature of the subterranean formation to which the gelable aqueous silicate composition will be introduced. The temperature-activated catalysts that can be used in the gelable aqueous silicate compositions of the present invention include, but are not limited to, ammonium sulfate (which is most suitable in the range of from about 60° F. to about 240° F.); sodium acid pyrophosphate (which is most suitable in the range of from about 60° F. to about 240° F.); citric acid (which is most suitable in the range of from about 60° F. to about 120° F.); and ethyl acetate (which is most suitable in the range of from about 60° F. to about 120° F.). Generally, the temperature-activated catalyst is present in the gelable aqueous silicate composition in the range of from about 0.1% to about 5% by weight of the gelable aqueous silicate composition.

In other embodiments, the consolidation fluids suitable for use in the methods of the present invention comprise a crosslinkable aqueous polymer compositions. Generally, suitable crosslinkable aqueous polymer compositions comprise an aqueous solvent, a crosslinkable polymer, and a crosslinking agent. Such compositions are similar to those used to form gelled treatment fluids, such as fracturing fluids, but, according to the methods of the present invention, they are not exposed to breakers or de-linkers, and so they retain their viscous nature over time.

The aqueous solvent may be any aqueous solvent in which the crosslinkable composition and the crosslinking agent may be dissolved, mixed, suspended, or dispersed therein to facilitate gel formation. For example, the aqueous solvent used may be fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.

Examples of crosslinkable polymers that can be used in the crosslinkable aqueous polymer compositions include, but are not limited to, carboxylate-containing polymers and acrylamide-containing polymers. Preferred acrylamide-containing polymers include polyacrylamide, partially hydrolyzed polyacrylamide, copolymers of acrylamide and acrylate, and carboxylate-containing terpolymers and tetrapolymers of acrylate. Additional examples of suitable crosslinkable polymers include hydratable polymers comprising polysaccharides and derivatives thereof and that contain one or more of the monosaccharide units galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate. Suitable natural hydratable polymers include, but are not limited to, guar gum, locust bean gum, tara, konjak, tamarind, starch, cellulose, karaya, xanthan, tragacanth, and carrageenan, and derivatives of all of the above. Suitable hydratable synthetic polymers and copolymers that may be used in the crosslinkable aqueous polymer compositions include, but are not limited to, polyacrylates, polymethacrylates, polyacrylamides, maleic anhydride, methylvinyl ether polymers, polyvinyl alcohols, and polyvinylpyrrolidone. The crosslinkable polymer used should be included in the crosslinkable aqueous polymer composition in an amount sufficient to form the desired gelled substance in the subterranean formation. In some embodiments of the present invention, the crosslinkable polymer is included in the crosslinkable aqueous polymer composition in an amount in the range of from about 1% to about 30% by weight of the aqueous solvent. In another embodiment of the present invention, the crosslinkable polymer is included in the crosslinkable aqueous polymer composition in an amount in the range of from about 1% to about 20% by weight of the aqueous solvent.

The crosslinkable aqueous polymer compositions of the present invention further comprise a crosslinking agent for crosslinking the crosslinkable polymers to form the desired gelled substance. In some embodiments, the crosslinking agent is a molecule or complex containing a reactive transition metal cation. A most preferred crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water. Examples of suitable crosslinking agents include, but are not limited to, compounds or complexes containing chromic acetate and/or chromic chloride. Other suitable transition metal cations include chromium VI within a redox system, aluminum III, iron II, iron III, and zirconium IV.

The crosslinking agent should be present in the crosslinkable aqueous polymer compositions of the present invention in an amount sufficient to provide, inter alia, the desired degree of crosslinking. In some embodiments of the present invention, the crosslinking agent is present in the crosslinkable aqueous polymer compositions of the present invention in an amount in the range of from about 0.01% to about 5% by weight of the crosslinkable aqueous polymer composition. The exact type and amount of crosslinking agent or agents used depends upon the specific crosslinkable polymer to be crosslinked, formation temperature conditions, and other factors known to those individuals skilled in the art.

Optionally, the crosslinkable aqueous polymer compositions may further comprise a crosslinking delaying agent, such as a polysaccharide crosslinking delaying agent derived from guar, guar derivatives, or cellulose derivatives. The crosslinking delaying agent may be included in the crosslinkable aqueous polymer compositions, inter alia, to delay crosslinking of the crosslinkable aqueous polymer compositions until desired. One of ordinary skill in the art, with the benefit of this disclosure, will know the appropriate amount of the crosslinking delaying agent to include in the crosslinkable aqueous polymer compositions for a desired application.

In other embodiments, the consolidation fluids suitable for use in the methods of the present invention comprise polymerizable organic monomer compositions. Generally, suitable polymerizable organic monomer compositions comprise an aqueous-base fluid, a water-soluble polymerizable organic monomer, and a primary initiator. Optionally, the polymerizable organic monomer compositions may also include an oxygen scavenger and/or a surfactant.

The aqueous-based fluid component of the polymerizable organic monomer composition generally may be fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components used in accordance with this invention or with the subterranean formation.

A variety of monomers are suitable for use as the water-soluble polymerizable organic monomers in the present invention. Examples of suitable monomers include, but are not limited to, acrylic acid, methacrylic acid, acrylamide, methacrylamide, 2-methacrylamido-2-methylpropane sulfonic acid, 2-dimethylacrylamide, vinyl sulfonic acid, N,N-dimethylaminoethylmethacrylate, 2-triethylammoniumethylmethacrylate chloride, N,N-dimethyl-aminopropylmethacryl-amide, methacrylamidepropyltriethylammonium chloride, N-vinyl pyrrolidone, vinyl-phosphonic acid, and methacryloyloxyethyl trimethylammonium sulfate, and mixtures thereof. Preferably, the water-soluble polymerizable organic monomer should be self-crosslinking. Examples of suitable monomers which are self crosslinking include, but are not limited to, hydroxyethylacrylate, hydroxymethylacrylate, hydroxyethylmethacrylate, N-hydroxymethylacrylamide, N-hydroxymethyl-methacrylamide, polyethylene glycol acrylate, polyethylene glycol methacrylate, polypropylene gylcol acrylate, polypropylene glycol methacrylate, and mixtures thereof. Of these, hydroxyethylacrylate is preferred. An example of a particularly preferable monomer is hydroxyethylcellulose-vinyl phosphoric acid.

The water-soluble polymerizable organic monomer (or monomers where a mixture thereof is used) should be included in the polymerizable organic monomer composition in an amount sufficient to form the desired gelled substance after placement of the polymerizable organic monomer composition into the subterranean formation. In some embodiments of the present invention, the water-soluble polymerizable organic monomer is included in the polymerizable organic monomer composition in an amount in the range of from about 1% to about 30% by weight of the aqueous-base fluid. In another embodiment of the present invention, the water-soluble polymerizable organic monomer is included in the polymerizable organic monomer composition in an amount in the range of from about 1% to about 20% by weight of the aqueous-base fluid.

The presence of oxygen in the polymerizable organic monomer composition may inhibit the polymerization process of the water-soluble polymerizable organic monomer or monomers. Therefore, an oxygen scavenger, such as stannous chloride, may be included in the polymerizable monomer composition. In order to improve the solubility of stannous chloride so that it may be readily combined with the polymerizable organic monomer composition on the fly, the stannous chloride may be pre-dissolved in a hydrochloric acid solution. For example, the stannous chloride may be dissolved in a 0.1% by weight aqueous hydrochloric acid solution in an amount of about 10% by weight of the resulting solution. The resulting stannous chloride-hydrochloric acid solution may be included in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 10% by weight of the polymerizable organic monomer composition. Generally, the stannous chloride may be included in the polymerizable organic monomer composition of the present invention in an amount in the range of from about 0.005% to about 0.1% by weight of the polymerizable organic monomer composition.

The primary initiator is used, inter alia, to initiate polymerization of the water-soluble polymerizable organic monomer(s) used in the present invention. Any compound or compounds that form free radicals in aqueous solution may be used as the primary initiator. The free radicals act, inter alia, to initiate polymerization of the water-soluble polymerizable organic monomer present in the polymerizable organic monomer composition. Compounds suitable for use as the primary initiator include, but are not limited to, alkali metal persulfates; peroxides; oxidation-reduction systems employing reducing agents, such as sulfites in combination with oxidizers; and azo polymerization initiators. Preferred azo polymerization initiators include 2,2′-azobis(2-imidazole-2-hydroxyethyl) propane, 2,2′-azobis(2-aminopropane), 4,4′-azobis(4-cyanovaleric acid), and 2,2′-azobis(2-methyl-N-(2-hydroxyethyl) propionamide. Generally, the primary initiator should be present in the polymerizable organic monomer composition in an amount sufficient to initiate polymerization of the water-soluble polymerizable organic monomer(s). In certain embodiments of the present invention, the primary initiator is present in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 5% by weight of the water-soluble polymerizable organic monomer(s). One skilled in the art will recognize that as the polymerization temperature increases, the required level of activator decreases.

Optionally, the polymerizable organic monomer compositions further may comprise a secondary initiator. A secondary initiator may be used, for example, where the immature aqueous gel is placed into a subterranean formation that is relatively cool as compared to the surface mixing, such as when placed below the mud line in offshore operations. The secondary initiator may be any suitable water-soluble compound or compounds that may react with the primary initiator to provide free radicals at a lower temperature. An example of a suitable secondary initiator is triethanolamine. In some embodiments of the present invention, the secondary initiator is present in the polymerizable organic monomer composition in an amount in the range of from about 0.1% to about 5% by weight of the water-soluble polymerizable organic monomer(s).

Also optionally, the polymerizable organic monomer compositions of the present invention further may comprise a crosslinking agent for crosslinking the polymerizable organic monomer compositions in the desired gelled substance. In some embodiments, the crosslinking agent is a molecule or complex containing a reactive transition metal cation. A most preferred crosslinking agent comprises trivalent chromium cations complexed or bonded to anions, atomic oxygen, or water. Examples of suitable crosslinking agents include, but are not limited to, compounds or complexes containing chromic acetate and/or chromic chloride. Other suitable transition metal cations include chromium VI within a redox system, aluminum III, iron II, iron III, and zirconium IV. Generally, the crosslinking agent may be present in polymerizable organic monomer compositions in an amount in the range of from 0.01% to about 5% by weight of the polymerizable organic monomer composition.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations are considered within the scope and spirit of the present invention. All numbers and ranges disclosed above may vary slightly. Moreover, any numerical range defined by two R numbers as defined in the above is also specifically disclosed. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. 

1. A method comprising: placing a treatment fluid into a well bore that penetrates a subterranean formation, wherein the subterranean formation comprises at least one selected from the group consisting of: a shale, a clay, a coal bed, and a combination thereof; and applying a pressure pulse to the treatment fluid.
 2. The method of claim 1 wherein the subterranean formation further comprises at least one fracture and the treatment fluid is placed into the subterranean formation so that the at least one fracture is at least partially dilated.
 3. The method of claim 1 further comprising pressurizing the treatment fluid above the ambient fluid pressure in the well bore prior to applying the pressure pulse.
 4. The method of claim 1 wherein the pressure pulse exceeds the formation fracture gradient.
 5. The method of claim 1 wherein the pressure pulse straddles the formation fracture gradient.
 6. The method of claim 1 wherein the subterranean formation further comprises one or more pairs of adjacent bedding planes and the treatment fluid is placed into the subterranean formation so that the one or more pairs of adjacent bedding planes is at least partially separated.
 7. The method of claim 1 wherein the pressure pulse applied to the treatment fluid generates a pressure pulse in a portion of the subterranean formation in the range of from about 10 psi to about 3,000 psi.
 8. The method of claim 1 wherein the pressure pulse is applied at a frequency in the range of from about 0.001 Hz to about 1 Hz.
 9. The method of claim 1 further comprising generating a pressure pulse having an amplitude different from the amplitude of a previous pressure pulse.
 10. The method of claim 1 further comprising at least one of the following: allowing the treatment fluid to at least partially dehydrate at least a portion of the subterranean formation; allowing the treatment fluid to at least partially stabilize at least a portion of the subterranean formation; and allowing the treatment fluid to at least partially shrink at least a portion of the subterranean formation.
 11. The method of claim 1 wherein the treatment fluid comprises at least one selected from the group consisting of: a cationic polymer; a cationic oligomer; a methanol; a glycerin; an ethylene glycol; a low molecular weight consolidation fluid; a polymeric composition; a quaternary ammonium compound having inorganic anions and carboxylate anions; a polymeric composition; a rheology stabilizer; a rheology thinner; a consolidation fluid; a stimulation fluid; a relative permeability modifier; and a combination thereof.
 12. The method of claim 1 wherein the treatment fluid comprises at least one selected from the group consisting of: a potassium ion, a calcium ion, an ammonium ion, a hydrogen ion, a tetramethylammonium ion, potassium chloride, calcium chloride, sodium chloride, ammonium chloride, tetramethylammonium chloride, and a combination thereof.
 13. A method comprising: placing a treatment fluid into a well bore that penetrates a subterranean formation, wherein the subterranean formation comprises at least one selected from the group consisting of: a shale, a clay, a coal bed, and a combination thereof; and applying a pressure pulse that exceeds the formation fracture gradient to the treatment fluid.
 14. The method of claim 13 further comprising pressurizing the treatment fluid above the ambient fluid pressure in the well bore prior to applying the pressure pulse.
 15. The method of claim 13 further comprising at least one of the following: allowing the treatment fluid to at least partially dehydrate at least a portion of the subterranean formation; allowing the treatment fluid to at least partially stabilize at least a portion of the subterranean formation; and allowing the treatment fluid to at least partially shrink at least a portion of the subterranean formation.
 16. The method of claim 13 wherein the treatment fluid comprises at least one selected from the group consisting of: a cationic polymer; a cationic oligomer; a methanol; a glycerin; an ethylene glycol; a low molecular weight consolidation fluid; a polymeric composition; a quaternary ammonium compound having inorganic anions and carboxylate anions; a polymeric composition; a rheology stabilizer; a rheology thinner; a consolidation fluid; a stimulation fluid; a relative permeability modifier; and a combination thereof.
 17. The method of claim 13 wherein the treatment fluid comprises at least one selected from the group consisting of: a potassium ion, a calcium ion, an ammonium ion, a hydrogen ion, a tetramethylammonium ion, potassium chloride, calcium chloride, sodium chloride, ammonium chloride, tetramethylammonium chloride, and a combination thereof.
 18. A method comprising: placing a treatment fluid into a well bore that penetrates a subterranean formation, wherein the subterranean formation comprises at least one selected from the group consisting of: a shale, a clay, a coal bed, and a combination thereof; pressurizing the treatment fluid to a first pressure wherein the first pressure exceeds the ambient fluid pressure in the well bore; and applying a pressure pulse to the treatment fluid, wherein the minimum pressure of the pressure pulse exceeds the first pressure; and the maximum pressure of the pressure pulse exceeds the formation fracture gradient.
 19. The method of claim 18 wherein the minimum pressure of the pressure pulse exceeds the formation fracture gradient.
 20. The method of claim 18 wherein the treatment fluid comprises at least one selected from the group consisting of: a cationic polymer; a cationic oligomer; a cation; a methanol; a glycerin; an ethylene glycol; a low molecular weight consolidation fluid; a polymeric composition; a quaternary ammonium compound having inorganic anions and carboxylate anions; a polymeric composition; a rheology stabilizer; a rheology thinner; a consolidation fluid; a stimulation fluid; a relative permeability modifier; and a combination thereof. 